Dual zone completion system with special valve



E. D. YETMAN Feb. 7, 1967 DUAL ZONE COMPLETION SYSTEM WITH SPECIAL VALVE 4 SheetsSheet 1 Filed Feb. 28, 1964 FIG.

FIG.

FIG. 4

INVENTOR'.

EDWARD D. YETMAN BYI FIG. 6

HIS ATTORNEY E. D. YETMAN 3392,?21

DUAL ZONE COMPLETION SYSTEM WITH SPECIAL VALVE Feb 7, 3%67 4 Sheets-Sheet 2 Filed Feb. 28, 1964 UPPER ZONE LOWER ZONE INVENTORI EDWARD D. YETMAN BY:

H|S ATTORNEY m r. E. D. YEQMAN 33%321 DUAL ZONE COMPLETION SYSTEM WITH SPECIAL VALVE Feb. 7 196'? 4 Sheets-$heet 5 Filed Feb. 28, 1964 lNVENTORI FiG. 3A

EDWARD D. YETwgm avig fl/mww HIS ATTORNEY Feb. y, 19%? E D. YETMAN 9 DUAL ZONE COMPLETION SYSTEM WITH SPECIAL VALVE Filed Feb. 28, 1964 4 Sheets-Sheet 4 1f 7 A UPPER 9?;

m PER ZONE 2;

INVENTORI EDWARD D. YETMAN H38 ATTORNEY United States Patent 3,302,721 DUAL ZONE COMZLETION SYSTEM WITH SPECIAL VALVE Edward D. Yetman, Bakersfield, Calif, assignor to Shell Gil Company, New York, N.Y., a corporation of Delaware Filed Feb. 28, 1964, Ser. No. 348,176 7 Claims. (Cl. 16645) This invention relates to the completion of wells having two distinct producing zones and pertain more particularly to a valve adapted to be pumped down a well tubing in the dual completion system to prevent downthe-hole commingling of fluids from the two zones.

The invention is especially suited for through-the-flowline operation of underwater wells. Through-the-flowline operations refer to techniques wherein well completion and operation procedures are conducted by tools which pass through a flowline communicating between a surface location, such as an operating station, and a submerged well installation, movement of the tool being caused by pumping a driving fluid through the flowline. In order to carry out some of the more simple workover or maintenance operations, such as the removal of a valve, the cleaning of parafiin from a tubing string, etc., it has been necessary to develop an entirely new line of well tools which can be pumped through a production flowline from some remote location, oftentimes a mile or more from the well, and enter the well, passing down the tubing string therein to be subsequently positioned therein for carrying out some preselected operation. After completing the operation, the tool in the tubing string within the well is subsequently removed, generally by reverse circulation of the driving fluid.

Through-the-flowline operations become more diflicult where the tubing strings, through which the flowline tools must pass, extend into two fluid producing zones rather than a single producing zone. Since the quality of the fluid produced in one zone may be greatly superior to that produced in the other, it is desirable, for practical reasons, to keep the fluids from the two zones separate. In addition, many states have regulations which forbid the commingling of fluids from separate producing zones.

Broadly, this invention presents a solution to the aforementioned problems by providing a dual completion system for producing both zones with a minimum amount of tubing strings extending into each zone, and whereby through-the-flowline work can be performed in either of the zones without commingling of fluids from the two zones. The system comprises three tubing strings, one extending into the first producing zone, a second extending into the second producing zone, and a third extending into at least the first producing zone. A first branch tubing connects the first tubing string to the third, forming a first fluid circuit, and a second branch tubing connects the second tubing string to the third forming a second fluid circuit. A valve is provided at the juncture of these two circuits for selectively controlling fluid flow through one or the other of the two circuits. With this arrangement, it is possible to perform through-the-flowline operations in one zone while maintaining production in the other zone, and at the same time prevent commingling of fluids from the two zones. In a preferred embodiment of the invention such a valve is a two-position valve although it is recognized that a one-position valve having two conditions could be utilized.

These and other advantage of this invention will be understood from the following description taken with reference to the drawings, wherein:

FIGURE 1 is a schematic view in partial longitudinal section illustrating a wellhead assembly positioned on the ocean floor;

3,3fl2,72l Patented Feb. 7, 1967 FIGURE 2 is a diagrammatic view taken in partial longitudinal section of one arrangement of the dual completion system together with the two-position valve of the present invention;

FIGURES 3A, 3B and 3C show the valve together with a tool carrier and latching means within a tubing string for keeping the valve in one position;

FIGURE 4 is a view partially in section showing the valve in a second position;

FIGURES 5 and 6 show different probes which can be used with the latching mechanism; and,

FIGURES 7l0 are schematic views taken in partial longitudinal section showing an alternative form of the invention.

Referring to FIGURE 1 of the drawings, a wellhead assembly is shown as positioned below the surface 11 of a body of water and preferably on the ocean floor 12. The wellhead apparatus comprises a platform 13 secured to the top of a conductor pipe or surface casing 14 which in turn extends into the earth below the body of water and is preferably cemented therein in a conventional manner. The wellhead assembly may also be provided with two or more vertically-positioned guide columns 15 and 16 which are fixedly secured at their lower ends to the platform 13. A well casinghead 17 is mounted on the top of a conductor pipe 14 with a control equipment housing 18 closing the top of casinghead and/ or any casing and tubing suspension equipment employed on the well head assembly, as well as the various control valves and other equipment normally used on the top of a well of this type.

Emerging from the housing 18 are four flowlines 20, 21, 22 and 23 which preferably bend in long sweeping curves from a vertical position down to a substantially horizontal position so that they can run along the ocean floor 12 to a remote location where fluid from the well, and normally from other wells, is collected and metered and treated. Such a collection station may be several miles away. The well may be provided with one or more strings of well casing 24 suspended within the conductor pipe 14. The flowlines 26, 21 and 22, in the particular installation illustrated, are in communication with three tubing strings 25, 26 and 27, respectively, depending within the well. The flowline 23 is in communication with the annular space between the tubing strings 25, 26 and 27 and the adjacent well casing 24. The tubing strings and 26 are shown as being provided with a series of valve housings or side pockets 28 spaced there along wherein gas-lift valve may be positioned.

In FIGURE 2 the lower ends of the three tubing strings 25, 26 and 27 are shown secured within the Well casing 24 by suitable packers or well partition elements 32 and 33. The tubing string 27 is provided with recessed annular latching bores 29 and 30. Tubing string 27 is also provided with a reduced-diameter portion which forms a seating shoulder 31 near its lower end, and similar seating shoulders may be provided in tubing strings 25 and 26. Branch pipe 34 connects tubing string 26 to tubing string 27 and branch pipe 35 connects tubing string 25 to tubing string 27. Thus, it can be seen that a first fluid circuit is formed by tubing string 26, branch pipe 34 and that portion of tubing string 27 extending above branch pipe 34, while a second fluid circuit is formed by tubing string 25, branch pipe 35 and the entire length of tubing string 27. It should be noted that the two circuits have a common portion, namely that portion of tubing string 27 which is situated above its juncture with the branch pipe 34. Tubing string 26 is open at the bottom and extends into an upper or first fluid zone; it is provided with a check valve 36 which prevents the pumping of fluid into the upper zone. A similar check valve 37 is located in the lower end of tubing string 25 to prevent the pumping of fluid into the lower or second zone, the tubing string being also open at the bottom. Packer 33 separates the two zones, which may be several hundred feet apart. Packer 32 could be eliminated but is preferred because it add stability to the system. Well casing 24 is provided with perforations 44 to allow fluid from the two producing formations outside the well to flow into the casing.

In order to carry out through-the-flowline operations in one of the tubing strings 25 or 26, without commingling fluids from the two zones, a two-position valve or conduit closure means in accordance with the present invention is provided. The two-position valve of the present invention employs a two-piece tubular mandrel comprising body members 38 and 39 which are connected together together preferably by flexible joint 40. As illustrated in FIGURE 3B, the joint 40 includes a first annular flange 41 fixed to the lower end of body member 38 and a second annular flange 42 fixed to the upper end of body member 39. The flanges 41 and 42 are dimensioned so as to be loosely received within cylindrical section 43, thus maximizing the flexibility of the elements joined thereby. The flexible joint 40 facilitates passage of the two-piece mandrel through curved sections of the flowline. The lower portion 45 of member 39 is of reduced diameter and is provided with a cylindrical pack body or sealing member 46 for sealingly engaging the walls of tubing string 27 below the seating shoulder 31. A circumferential flange or stop shoulder 47 is located above the reduced-diameter portion 45 of member 39 and is large enough to contact and be stopped by the seating shoulder 31. A plurality of fluid passages 48 are formed in stop shoulder 47 and communicate with a central bore 49 which runs longitudinally through the major portion of member 39. Ports 50 are located below the annular flange 42 and are also in fluid communication with the bore 49. Pack bodies or sealing elements 51 and 52 are arranged at vertically spaced locations in circumferential grooves in the major portion of member 39 for sealing engagement with the inner walls of tubing string 27.

As shown in FIGURES 3A and 3B, the body member 38 is provided with a central bore 55 which runs through the entire length of member 38 and is in fluid communication with bore 49 of body member 39. The body member 38 includes a latching device for keeping member 39 in one of two positions. According to a preferred form, a pair of radially extensible latching dogs 56 and 57 are pivotally mounted below their mid-heights near the lower end of body member 38. Dogs 56 and 57 are spring biased for radial outward movement of their upper portions into either of the latching bores 29 or 30 and function to lock the members 38 and 39 against upward movement through tubing string 27. Located near the top of member 38 are two similar radially extensible latching dogs 58 and 59. Dog 58 is spring biased for radial outward movement of its upper portion into one of the latching bores 29 or 30 to lock members 38 and 39 against upward movement. Dog 59 is similarly spring biased for radial outward movement of its lower portion into one of the latching bores 29 or 30 but locks members 38 and 39 against movement in the downward direction. Although only one dog 58 and one dog 59 are shown it is to be understood that a pair of each type of dog could be used.

In order to propel the two-piece valve or conduit closure means 38 and 39 through tubing string 27, a tool carrier of any suitable type may be connected to the upper end of member 38. The tool carrier 61 (FIGURE 3A) comprises a central mandrel having sections 62 and 63 with axially spaced sealing elements or packers 64 and 65 mounted thereon. Packers 64 and 65 may be made of rubber or certain plastic materials. Preferably a ball-insocket joint 66 joins sections 62 and 63 together so as to facilitate movement of the tool carrier 61 in curved sections of the flowline. Fluid ports 67 and 68 are provided through the walls of sections 62 and 63 so that fluid may enter the inside of the packers 64 and to inflate and expand them against the inner walls of tubing string 27. The internal details of the tool carrier 61 are not the subject of my invention and may take any suitable form, such as that shown in US. Patent 3,052,302 to Lagucki or US. Patent 3,050,130 to Culver et a1.

During use of the tool carrier of FIGURE 3A, a pressure fluid enters ports 67 so that packer element 64 is forced against the inner wall of tubing string 27 thus causing the packer element to act as a piston, whereby the tool carrier 61 is forced downwardly through the tubing string 27. This action takes place since a pressure differential exists across the upper sealing element 64 whereas no pressure differential exists across the sealing element 65 on downward travel of the tool carrier, since the fluid pressures on opposite sides of the lower sealing element are the same and there is therefore no tendency for the sealing element 65 to expand against the wall of tubing string 27. Thus, it may be seen that, on the downward travel of the present tool carrier, the upper sealing element 64 maintains a tight fit against the tubing 27 at all times, while the lower sealing element 65 merely acts as an inoperative piston which would not contact the tubing wall 27 with any force to form a seal thereagainst.

In returning tool carrier 61 with or without its accompanying two-piece conduit closure means 38, 39 circulation of the driving fluid in the tubing string 27 is reversed so that the pressure fluid moves upwardly through the tubing string v27. The upwardly directed driving fluid enters port 68 and forces the sealing element 65 against the tubing string 27 so that the actions of the sealing elements 64 and 65 are reversed, with the sealing element 65 acting as the piston and the sealing element 64 acting as an idler.

The tool carrier 61 is preferably provided with a fishinghead whereby a retrieving tool (not shown) may be run through the tubing string 27 to latch onto the fishinghead 70, thereby permitting removal of the tool carrier should it become stuck in the tubing. The retrieving tool may take the form of another tool carrier having latching means carried on its lower end to connect onto the fishinghead 70 of the tool carrier stuck within the well.

Attached to the lower end of the tool carrier 61 is a latch-actuating tool 72 adapted to be disconnected from body member 38 after the two-piece conduit closure means 38, 39 has been run into place. A preferred form of latch-actuating device comprises a probe-like element 73 which is threadedly secured to the bottom of a generally cylindrical body 74 having a split spring locking ring 75 carried on a downwardly and outwardly tapered shoulder 76 formed on the outside of body 74. The normal diameter of the split spring locking ring 75 is of a size to contact a shoulder (at the top of body member 38) when moved against it in an upward direction. At the same time the split spring locking ring 75 may be contracted sufliciently to pass shoulder 80 when moving downwardly therethrough. Just below the tapered shoulder 76 is a downwardly slidable ring 77 pinned in place by shear pins 78 to the body 74 of the mechanism. A retaining ring 79 is provided within an annular recess below the shear pin ring 77 for holding the latter on the body 74 after the shear pins 78 have been sheared. The external diameter of the shear pin ring 77 is slightly greater than that of the widest part of the tapered shoulder 76, so that on being forced downwardly the locking spring ring 75 will contact the top of the shear pin ring 77. The probe 73 is designed to slip into the bore 55 of member 38 and contact the inner surfaces of latching dogs 58 and 59 and prevent them from moving outwardly into the annular recesses 29 and 30.

A shorter probe 81 is shown in FIGURE 5. When the probe 81 is used with the latch-actuating tool 72, the dog 58 is free to pivot outwardly into one of the latching bores 29 or 30 to lock members 38 and 39 against upward movement; the dog 59 is, however, locked in the retracted position shown.

The long probe 82, shown in FIGURE 6 is used With the latch-actuating tool 72 when it is desired to have all the dogs 56-59 remain in a retracted position.

During normal operation of the well, tubing string 27 would not be in use and could be closed off either at the wellhead or at some surface location. Fluid from the upper Zone would then be transported via tubing 26 to a collecting station and likewise fluid from the lower zone would be transported to a collecting station via tubing 25. However, in order to carry out work-over operations in either tubing string 25 or 26 it is necessary to open tubing string 27 to establish fluid circuits through which flowline tools may be passed. For example, it may be necessary during the life of the well to replace the check valves 36 and 37 or to insert a gas lift valve in one of the side pockets 28.

v The operation of the apparatus of the present invention will first be described with regard to establishing a fluid circuit between tubing strings 25 and 27. The entire apparatus comprising the tool carrier 61 with the sealing elements 64 and 65, the latch-actuating device 72 with probe element 73, and the two-piece valve with body members 38 and 39 are connected together and inserted into the flowline 22 (FIGURE 1) at a distant point, such for example, as a production platform or an installation on shore. A source of pressure fluid (not shown) is connected to the flowline 22 in back of the apparatus which has been inserted in the line, and the fluid is pumped through the line 22 in back of the tool carrier 61 until it has passed over the curved section of the flowline 22 and enters the wellhead assembly where it passes down the tubing string 27. The tool carrier 61 and the valve body members 38 and 39 continue to pass down through the tubing string 27 until the body member 39 stops when stop shoulder 47 comes into contact with the landing shoulder 31. Since the medium-length probe 73 is used during this operation, the dogs 58 and 59 are retracted and dogs 56 and 57 are released (FIGURES 3A and 3B).

Circulation is now reversed so that the pressure fluid flows down tubing string 25, through the branch pipe or cross over 35 and upwards through tubing string 27. This reverse circulation causes valve body member 39 to move upwardly until dogs 56 and 57 engage in the lower latching bore 38 (FIGURES 2 and 3B).

The tool carrier 61 having sealing elements 64 and 65 and the probe 73 are extracted from the body member 38 in the following manner as the body members 38 and 39 are held in position by dogs 56 and 57. Upward pressure of fluid forces the body 74 of the latch-actuating mechanism (FIGURE 3A) upwardly until the locking spring ring 75 contacts the shoulder 80 at the top of the body member 38. As the body 74 of the latch-actuating mechanism continues to move upwardly, the split ring 75 is forced down the tapered shoulder 76 until it contacts the top ofthe shear-pin ring 77. An increase in the fluid pressure causes the shear pins 78, which are preferably bronze or some other soft metal, in this operation, to shear and the shear pin ring 77 is initially prevented by the ring 75 from travelling upward, allowing the split ring 75 to move downwardly relatively to the tapered shoulder 76 and contract to a smaller diameter below the shoulder. The ring 77 is then free to move upwards out of the top of the body member 38 when engaged by the ring 79. With the latch-actuating assembly 72 and probe 73 free of the housing 38, these elements move upwardly through the tubing 27 with the tool carrier 61 where this portion of the apparatus can be retrieved at, for example, a well platform manifold.

With the probe 73 removed from the top of the housing 38, the dogs 58 and 59 are free to engage in the upper latching bore 29. The two-piece valve 38, 39 is now positioned as shown in FIGURE 2 and movement of the valve is prevented in the downward direction by dog 59 and in the upward direction by dogs 56, 57 and 58. As shown in FIGURES 2 and 3, sealing elements 51 and 52 prevent fluid communication between tubing strings 27 and 26. A fluid circuit has been established in which fluid flow from tubing string 25 to tubing string 27 and reverse is through the fluid passages 48 and the bores 49 and 55 of the two-piece valve member. With the valve in this position pumping operations to set or remove a valve in side pocket 28, etc., may be carried out in tubing string 25, while at the same time fluid from the upper zone may be passed upwardly through tubing string 26 without danger of comrningling fluids between the upper and lower zones.

When it is desired to carry out pumping operations in tubing string 26, the tool carrier 61 with the short probe 81 (FIGURE 5) is pumped down tubing string 27 and upon engaging member 38 the dog 59 is retracted, allowing the two-piece valve to be pumped downwardly. Valve member 39 moves downwardly until the stop shoulder 47 engages the seating shoulder 31 of the tubing string 27. Since the dog 58 is not retracted by the short probe 81, it moves outwardly into the lower latching bore 30 thereby locking the body members 38 and 39 against upward movement. The valve member 39 is now positioned so that the small diameter pack body 46 is sealingly engaged with the walls of tubing string 27 below the seating shoulder 31, the sealing element 51 is now in the position formerly occupied by sealing element 52 and the ports 50 are in fluid communication with branch pipe 34 (FIGURE 4). Upon reversing the circulation, fluid flows downwardly through tubing string 26, across the branch pipe 34 and up tubing string 27. Upward pressure of the fluid in tubing string 27 causes the shear pins 78 to break thereby freeing the tool carrier 61 and the probe 81 so that they may be retrieved at some surface location. Removal of the probe 81 from the top of member 38 allows the dog 59 to move radially outwardly into the lower latching bore 38. As shown in FIGURE 4, movement of the two-piece valve is prevented in the downward direction by the seating shoulder 31 and the dog 59, and in the upward direction by the dog 58. A fluid circuit has now been established between tubing strings 26 and 27. Fluid flow from tubing string 26 to tubing string 27 and reverse is through branch pipe 34-, into the port 58 of member 39, and then through the bore '55 in member 38. With the valve in this position, work-over operations may be carried out in tubing string 26 while at the same time fluid from the lower zone may be transported through tubing string 25 without danger of cornmingling fluids from the upper and lower zones.

To carry out work-over operations in tubing string 25 with the two-piece valve in the lower position just described (FIGURE 4) the tool carrier 61 with the probe 73 would be pumped down tubing string 27 to retract dogs 58 and 59 from latching bore 39. Upon .reverse circulation, the valve is pulled up until dogs 56 and 57 engage in the lower latching bore 38. Tool carrier 61 and probe 73 are retrieved upon shearing free and dogs 58 and 59 engage in upper latching bore 29. From the above description it can be seen that the utility of tubing string 27 can -be changed by one round trip of the carrier tool 61. If the entire two-piece valve is to be retrieved, the long probe 82 (FIGURE 6) is run which retracts all the dogs 56, 57, 58 and 59 and the valve is recovered by reverse circulation.

A more simplified form of producing fluids from two zones without commingling is shown in FIGURES 7-10. The apparatus shown in FIGURES 7-19 may be used where only two tubing strings extend into the casing.

In FIGURES 7-10 there is schematically shown a tubing string extending from the top of a wellhead (not shown) down through an upper producing zone into a lower producing zone. A similar tubing string 91 extends into the upper producing zone. The tubing string 90 has a valve shown schematically at 92 which may be 7 a hollow cylindrical member similar in construction to member 39 previously described in connection with FIG- URES 3A, 3B and 3C. However, for simplicity and ease of understanding, it is represented schematically in one of the two positions it may assume. In one position valve 92 prevents fluid communication between the upper zone and tubing string 90 but allows fluid to flow between the lower zone and tubing string 90. In a second position valve 92 permits fluid communication between the upper zone and tubing string 90. Packers 93 and 94 are seated in well casing 95 and separate the upper and lower zones. Well casing 95 is provided with perforations 96 to allow fluid from the two producing formations outside the well to flow inside the casing. A conduit 97 extends between the two packers 93 and 94 and provides fluid communication between the lower zone and the annulus 98. A conduit 99 is located near the upper end of casing 95 and fluid may flow between conduit 99 and the annulus 98 when the valve 100, located in conduit 99, is in the open position. A string of flowline tools has been schematically shown at 101 in FIGURES 8 and 9. In FIGURE 10, a series of gas lift valves are schematically shown at 102.

FIGURE 7 shows an operation wherein fluid is being produced from both the upper and lower zones in a normal manner. The valve 92 is shown in the closed position so that there is no fluid communication between the upper zone and tubing string 90. The valve 100 is also in closed position. Thus, fluid from the lower zone is being produced upwardly through tubing string 90 and fluid from the upper zone is being produced upwardly through tubing string 91.

FIGURE 8 shows an operation wherein a string of flowline tools 101 are being pumped into tubing string 90. The valve 92 is in the closed position with regard to the upper zone so that fluid from the upper zone is produced through tubing string 91 in an uninterrupted manner while flowline operations are being carried out in tubing string 90. Valve 100 is shown in the open position to establish a fluid circuit from tubing string 90 to conduit 97 and out conduit 99. To circulate flowline tools 101 out of tubing string 90 the circulation is reversed so that fluid flow is from conduit 99 to annulus 98, through conduit 97 and up tubing string 90.

FIGURE 9 shows an operation wherein a string of flowline tools 101 is being pumped into tubing string 91. The valve 92 is in the open position so that fluid from both the upper and lower zones flows into tubing string 90. Valve 100 is shown in closed position. With valve 92 in the open position a fluid circuit between tubing strings 90 and 91 is established which permits tools 101 to be pumped back and forth through tubing string 91. Since valve 92 is also open to the lower zone while flowline operations are being conducted in tubing string 91 there will be commingling of fluids from the upper and lower zones during this period.

FIGURE 10 shows an operation wherein it has become necessary to use conventional gas lift valves 102 to produce the fluids from both the upper and lower zones. The operation is in all respects identical with that shown in FIGURE 1 except that valve 100 is open so that gas may be passed from conduit 99 through the annulus 98 and to the gas lift valves 102.

I claim as my invention:

1. A method of establishing fluid communication selectively with one of two isolated fluid producing formations traversed by a well, comprising:

(a) partitioning the wellbore and establishing upper and lower separated zones within the wellbore respectively adjacent said two isolated producing formations and in flow communication therewith;

(b) establishing fluid flow communication from a location outside the well to one of said zones through first conduit means;

(c) establishing fluid flow communication from said location outside the well through said partitioned portion of the well bore to the other of said zones with second conduit means;

(d) providing fluid flow communication between each of said first and second conduits and said location outside the well through a common conduit;

(e) positioning conduit closure means in said common conduit in a first position that allows fluid flow communication between said common conduit and said first conduit and simultaneously blocks fluid flow communication between said common conduit and said second conduit; and,

(f) shifting said closure means to a second position within said common conduit that allows fluid flow communication between said common conduit and said second conduit and simultaneously blocks fluid flow communication between said common conduit and said first conduit.

2. The method of claim 1 wherein said step (e) includes pumping the conduit closure means from said location outside the well to a position in said common conduit and thereby selectively interrupting fluid communication between one of the zones and said common conduit.

3. A flowline system for establishing fluid communication selectively with each of two fluid producing formations traversed by a well, comprising:

(a) a wall structure including partition means positioned in the well to divide the well bore into upper and lower zones which are respectively adjacent said two producing formations, and in flow communication therewith;

(b) a first tubing string extending from the top of the well into said upper zone;

(c) a second tubing string extending from the top of the well down through said upper zone and said partition means into said lower zone;

((1) a common tubing string extending from the top of the well down into at least the upper zone;

(e) a first branch tubing connecting a lower portion of said first tubing string to the common tubing string thereby establishing a first fluid circuit between said first tubing string and said common tubing string;

(f) a second branch tubing connecting a lower portion of said second tubing string to the lower end of said common tubing string thereby establishing a second fluid circuit between said second tubing string and said common tubing string;

(g) and means for positioning a valve in said common tubing string at the juncture of said common tubing string with said first and second fluid circuits, said valve having means for selectively controlling fluid communication between said common tubing string and said first and second tubing strings.

4. The system of claim 3 wherein said valve is a twoposition valve having latching means adapted to selectively engage said common tubing string at axially spaced locations therein.

5. A flowline system as set forth in claim 4 wherein said common tubing string has a pair of spaced recessed latching bores located above the juncture of said first and second branch pipes with the common tubing string, and wherein said positioning means comprises:

(a) a pumpable tool carrier adapted to be pumped down said common tubing string;

(b) a first elongated cylindrical body member secured to the lower end of said tool carrier; and,

(c) radially extensible latching means carried by said first body member and adapted to engage said latching bores.

6. Apparatus for selectively establishing fluid communication between a tubing string depending within a well and one of two branch pipes connected thereto, said apparatus comprising:

(a) a vertical tubing string;

(b) a pair of recessed latching bores formed at axially spaced locations Within the tubing string;

(c) a first branch pipe communicating with said tubing string at a point below said latching bores;

(d) a seating shoulder formed by a reduced diameter portion of said tubing string at a point below said first branch pipe;

(e) a second branch pipe communicating with said tubing string at a point below said seating shoulder;

(f) a pumpable well device including a first body member of a diameter sufl'lcient to pass downwardly through said vertical tubing string to stop selectively at one of said recessed latching bores;

(g) bore means extending lengthwise down the center of said first body member;

(h) radially extensible latching means carried by said first body member and adapted to engage said recessed latching bores;

(i) a second body member of generally cylindrical shape secured to the lower end of said first body member and in fluid communication therewith;

(j) said second body member having a major portion of diameter sutficient to pass through said tubing string;

(1:) first and second axially spaced circumferential sealing members mounted externally on said major portion of the second body member;

(1) an internal bore extending longitudinally throughout the major portion of said second body member,

(m) means positioned above said first and second sealing means for establishing fluid communication between said internal bore and the exterior of said second body member;

(n) a circumferential stop shoulder located below said first and second sealing means and adapted to be engaged by said seating shoulder in said tubing string;

() means formed in said stop shoulder for establishing fluid communication between said internal bore of the second body member and the exterior of said second body member;

(p) said second body member having a reduced diameter portion extending downwardly below said stop shoulder; and,

5 be passed down a tubing string in a Well to a selected position thereof, said valve member comprising:

(a) an elongated body member of generally cylindrical shape;

(b) a major portion of said body member being of a diameter substantially equal to the diameter of said tubing string;

(c) first and second axially spaced circumferential sealing members externally mounted on said major portion of the body member;

(d) an internal bore extending longitudinally throughout the major portion of said body member;

(e) means formed in said body member at a point above said first and second sealing members for establishing fluid communication between said internal bore and the exterior of said body member;

(f) a circumferential inwardly directed stop flange formed in said major portion of the body member at a point below said first and second sealing members;

(g) means formed in said stop flange for establishing fluid communication between said internal bore and the exterior of said body member; and,

(h) a reduced diameter portion extending below said stop flange;

(i) said reduced diameter portion having circumferential sealing means externally mounted thereon.

References Cited by the Examiner UNITED STATES PATENTS 2,717,041 9/1955 Brown.

2,776,013 1/1957 Tausch.

3,032,117 5/1962 Tausch et al 166-45 X 3,064,580 11/1962 Calvert et al 16645 X 3,130,782 4/1964 Rike 166-154 X 3,132,694 5/1964 McGlasson et al. 166-151 X 3,182,726 5/1965 Stone t 16645 X ERNEST R. PURSER, Primary Examiner. 

1. A METHOD OF ESTABLISHING FLUID COMMUNICATION SELECTIVELY WITH ONE OF TWO ISOLATED FLUID PRODUCING FORMATIONS TRAVERSED BY A WELL, COMPRISING: (A) PARTITIONING THE WELBORE AND ESTABLISHING UPPER AND LOWER SEPARATED ZONES WITHIN THE WELLBORE RESPECTIVELY ADJACENT SAID TWO ISOLATED PRODUCING FORMATIONS AND IN FLOW COMMUNICATION THEREWITH; (B) ESTABLISHING FLUID FLOW COMMUNICATION FROM A LOCATION OUTSIDE THE WELL TO ONE OF SAID ZONES THROUGH FIRST CONDUIT MEANS; (C) ESTABLISHING FLUID FLOW COMMUNICATION FROM SAID LOCATION OUTSIDE THE WELL THROUGH SAID PARTITIONED PORTION OF THE WELL BORE TO THE OTHER OF SAID ZONES WITH SECOND CONDUIT MEANS; (D) PROVIDING FLUID FLOW COMMUNICATION BETWEEN EACH OF SAID FIRST AND SECOND CONDUITS AND SAID LOCATION OUTSIDE THE WELL THROUGH A COMMON CONDUIT; (E) POSITIONING CONDUIT CLOSURE MEANS IN SAID COMMON CONDUIT IN A FIRST POSITION THAT ALLOWS FLUID FLOW COMMUNICATION BETWEEN SAID COMMON CONDUIT AND SAID FIRST CONDUIT AND SIMULTANEOUSLY BLOCKS FLUID FLOW COMMUNICATION BETWEEN SAID COMMON CONDUIT AND SAID SECOND CONDUIT; AND, (F) SHIFTING SAID CLOSURE MEANS TO A SECOND POSITION WITHIN SAID COMMON CONDUIT THAT ALLOWS FLUID FLOW COMMUNICATION BETWEEN SAID COMMON CONDUIT AND SAID SECOND CONDUIT AND SIMULTANEOUSLY BLOCKS FLUID FLOW COMMUNICATION BETWEEN SAID COMMON CONDUIT AND SAID FIRST CONDUIT, 